Forming Mineral in Fractures in a Geological Formation

ABSTRACT

A system and method for hydraulically fracturing a geological formation with fracturing fluid to generate fractures in the geological formation and forming proppant in situ in the fractures by synthesizing mineral from ions in the fracturing fluid.

CLAIM OF PRIORITY

This application is a Continuation of and claims priority to U.S. patentapplication Ser. No. 16/397,710, filed on Apr. 29, 2019, the entirecontents of which is incorporated herein by reference.

TECHNICAL FIELD

This disclosure relates to fractures in a geological formation.

BACKGROUND

Hydraulic fracturing is generally applied after a borehole is drilledand a wellbore formed. Hydraulic fracturing is a well-stimulationtechnique in which rock is fractured by a pressurized liquid. Hydraulicfracturing employs fluid and material to generate fractures in ageological formation in order to stimulate production from oil and gaswells. The process can involve the pressurized injection of fracturingfluid into a wellbore to generate cracks in the deep-rock formationsthrough which natural gas, petroleum, and brine will flow more freely.Hydraulic fracturing may increase the flow of oil and gas from a well.The fracturing typically generates paths that increase the rate at whichproduction fluids can be produced from the reservoir formations. Theamount of increased production may be related to the amount offracturing.

Hydraulic fracturing may allow for the recovery of oil and natural gasfrom formations (for example, shale) that geologists once believed wereimpossible to produce. Hydraulic fracturing may be employed in tightsandstone, shale, and coal beds to increase crude oil or gas flow to awell from petroleum-bearing rock formations. Hydraulic fracturing can beapplied for vertical, horizontal, or deviated wellbores. A beneficialapplication may be horizontal wellbores in unconventional formationshaving hydrocarbons such as natural gas and crude oil. Proppants may beemployed to maintain the fractures open as pressure depletes in thewell.

SUMMARY

An aspect relates to a method of forming proppant in situ in ageological formation, including injecting a frac fluid through awellbore into the geological formation, and hydraulically fracturing thegeological formation with the frac fluid to generate fractures in thegeological formation. The method includes forming the proppant in situin the fractures in the geological formation via the frac fluid andhydrothermal synthesis.

Another aspect relates to a method of forming proppant in situ in ageological formation, including pumping a fracturing fluid through awellbore into the geological formation, and hydraulically fracturing thegeological formation with the fracturing fluid to generate fractures inthe geological formation. The method includes precipitating the proppantfrom the fracturing fluid on rock in the geological formation.

Yet another aspect relates to a method of forming a mineral in ageological formation, including injecting a frac fluid through awellbore into the geological formation and forming, via the frac fluid,the mineral on rock in the geological formation.

Yet another aspect relates to a method of forming a jarosite groupmineral in a geological formation, including pumping a fracturing fluidthrough a wellbore into the geological formation, and hydraulicallyfracturing the geological formation with the fracing fluid to generatefractures in the geological formation. The method includes synthesizingthe jarosite group mineral from iron ions and sulfate ions in thefracturing fluid via temperature of the geological formation, andprecipitating the jarosite group mineral to deposit the jarosite groupmineral as a crystallite on faces of the fractures.

Yet another aspect relates to a hydraulic fracturing system including avessel holding a fracturing fluid and a control component to modulate anaddition rate of an additive to the fracturing fluid in the vessel. Thesystem includes a pump (or plurality of pumps) to provide the fracturingfluid from the vessel through a wellbore into a geological formation tohydraulically fracture the geological formation to generate fractures inrock in the geological formation. The system includes a control systemto adjust a set point of the control component to change a concentrationof the additive in the fracturing fluid in response to a timing of thehydraulic fracturing and to alter a property of a jarosite matrix formedin the fractures via the fracturing fluid.

The details of one or more implementations are set forth in theaccompanying drawings and the description to be presented. Otherfeatures and advantages will be apparent from the description anddrawings, and from the claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is an image of a kerogen-rich shale sample containing pyriteminerals that are euhedral or framboidal.

FIG. 2A is a diagram of a crystal structure of the iron-sulfidemackinawite.

FIG. 2B is a diagram of a crystal structure of the iron-sulfide pyrite

FIG. 3 is a diagram of the general structure of jarosite.

FIG. 4 is sequence diagram of a well in a geological formation.

FIG. 5 is images of the shale treated with the oxidizing solution inExample 1.

FIG. 6A is an SEM image of the jarosite produced on the shale rock inExample 1.

FIG. 6B is a spectrum plot for the jarosite produced in Example 1.

FIG. 7A is a plot of iron concentration versus reaction temperature.

FIG. 7B is a plot of sulfate concentration versus reaction temperature.

FIG. 8A is an image of the residual solids from the bromate treatment ofpyrite in Example 2.

FIG. 8B is a PXRD spectrum plot of the residual solids of FIG. 8A.

FIG. 9 is a diagram of a well site having a wellbore formed through theEarth surface into a geological formation in the Earth crust.

FIG. 10 is a block flow diagram of a method of forming material (forexample, jarosite, proppant) in a geological formation.

Like reference numbers and designations in the various drawings indicatelike elements.

DETAILED DESCRIPTION

Unconventional reservoirs can include formations containing shale,sandstone, and coal beds. Unconventional formations can have apermeability of less than 1 millidarcy. The hydraulically fracturing ofthese formations typically forms a complex fracture network of primaryfractures and secondary microfractures surrounding the wellbore. Themicrofractures can extend from a primary fracture outwardly in abranching tree-like manner. These dendritic microfractures can be bothnear-wellbore and far field. Consequently, the secondary fractures ormicrofractures can give more depth and breadth to the fracture network.Rock volumes can be near-wellbore (for example, less than 10 feet fromwellbore), mid-field (for example, 10 feet to 100 feet from wellbore),and far field (for example, greater than 100 feet from wellbore).

Conventional or traditional proppant particulates (for example, havingparticle size greater than 150 microns) are typically too large to enterand prop open the microfractures. In the absence of sufficiently smallproppant particulates (for example, less than 150 microns), themicrofractures tend to close back once the hydraulic pressure placed onthe formation is released or decreased. Allowing the microfractures toclose eliminates a portion of the fracture network and reduces theproduction of hydrocarbons.

Present embodiments beneficially grow proppant in fractures including inmicrofractures and in the far field. Traditional proppant cannotpenetrate as deeply. With the present techniques, the pumping of asingle-phase carrier fluid and the accessibility of far-fieldmicrofractures and nanofractures can be advantageous. Traditional fluidwith proppant is multi-phase (slurry) that can suffer with settling ofthe proppant. Conversely, present embodiments promote transportproperties including to reach far field.

The present disclosure relates to in situ-generation of a mineral (forexample, jarosite) on rock in a geological formation. The formed mineralmay act as a proppant. Some aspects are directed to oxidative treatmentof pyrite in a geological formation to form jarosite proppant. Jarositeproppant may be formed in situ in a reservoir or geological formationupon oxidation of pyrite-containing rock or pyrite-containing kerogen.The proppant may thus be formed localized to the fractures and channelsincluding upon removal of kerogen by the aforementioned oxidizer or upongeneration of additional fractures by fracturing fluids having theoxidizer. The jarosite proppant may be placed to maintain pore structurewithout compromise of permeability.

Jarosite may be readily formed upon treatment of pyrite-containingkerogen or rock with oxidizers at elevated temperatures of thegeological formation. The oxidizers may be, for example, at least one ofbromate or chromate and may be associated with at least one of sulfateor persulfate. Examples to be presented demonstrate pyrite dissolution(giving, for example, Fe³⁺ and SO₄ ²⁻ ions) and the resulting jarositeformation and precipitation. In certain implementations, the jarositemay be grown in situ by addition of Fe³⁺ and SO₄ ²⁻ to the fracturingfluid. In particular embodiments, seawater (typically having SO₄ ²⁻content) can be utilized to prepare the fracturing fluid.

Embodiments provide for a partial replacement of the pumping ofproppants because of the in-situ formation of jarosite proppants. Forinstance, the amount of pumped proppants may be reduced by 5% to 70% byweight or volume for certain frac jobs. Some jarosite implementationsare directed to formation of small-mesh jarosite micro-proppants havingan average particle size, for example, of 100 mesh (150 μm), 200 mesh(75 μm), 400 mesh (35 μm), and 635 mesh (20 μm). These “in-situ grown”or “newly generated” jarosite are not pre-existing in the reservoir norpumped from surface. This jarosite serves as proppants by keeping thefracture path open for hydrocarbon production. The amount of proppantpumped from surface may be reduced because the jarosite group ofminerals formed in-situ serve as proppant. The jarosite group mineralsmay be formed in-situ by treatment fluid having the oxidizer when thetreatment fluid comes across or is exposed to pyrite in the geologicalformation.

This proppant replacing technology may mitigate issues of “proppanttransport” properties. The transport property of proppant is suspensionof the proppant within the fracturing treatment fluid without settlingdue to the proppant weight. Fracture treatment fluid having alightweight proppant (for example, non-ceramic proppant) has a bettertransport property than fracture treatment fluid having a ceramicproppant. Fracture treatment fluid not containing proppant particles iseven more efficient in transport through the fracture network. Thesingle-phase nature of the fracturing fluid benefits transport. Presentimplementations eliminate need for transport property promoting proppantflow for the portion of the fracturing job where the traditionalproppant is replaced.

The jarosite can be grown in-situ of varying heights and gradually infracturing applications from larger mesh (jarosite of >150 micrometer(μm) particle size) at near wellbore to smaller mesh (jarosite of <150μm particle size) in far field. In certain implementations at a start ofa frac job, fracturing fluid without oxidizer may be pumped to generatefractures. The pumping of fracturing treatment fluid having oxidizer maybe begin (for example, within the first 2 hours, first 3 hours, or first1-4 hours of the start of the frac job) for the generation of thejarosite matrix as proppants. The adjusting of the timing of injectingthe treatment fluid having the oxidizer may be to generate jarositematrix having a “spatial gradient” that provides a variance ofpermeability between near wellbore to far field in the fracturingapplication. There may be inter-grain porosity between the jarositecrystallites. The composition of the treatment fluid may be adjusted inreal time to generate jarosite matrix of varying packing density toprovide a differing permeability from near wellbore to far field in thefracturing application.

Some embodiments prevent or reduce damage due to proppant embedment.Externally pumped proppant could embed in the reservoir matrix causingreduction in fracture width and hence reduction in hydrocarbonconductivity. The external proppant could embed on the surface of afracture. Controlled growth of the jarosite layer on a fractured surfacemay give additional hardness to the fractured surface. The presence ofthe grown jarosite matrix may prevent or reduce embedment byconventional proppant on the fracture surface (face). As an example,consider a monolayer of 40/70-mesh traditional proppant when notembedded leaving a fracture width 200-400 μm. This fracture width can bereduced when the traditional proppant embeds. A Jarosite layer (forexample, 5-20 μm layer) formed on the fractured surface prior tosettling of the external proppant may provide a landing surface for theproppant and thus provide for retaining approximately the original200-400 μm fracture width. The jarosite layer may reduce damage causedby proppant embedment. Furthermore, edges of the jarosite embeddinglocally can create a network of a matrix plus fractures giving apermeability zone mitigating the permeability reduction cause byembedment of traditional proppant.

Conventional proppants hold open fractures generated in hydraulicfracturing. However, conventional proppants reduce the transportproperties of the fracturing fluids and are limited in penetration depthof petroleum reservoirs. The present techniques may beneficially reducethe amount of external proppant utilized in a given fracturingtreatment, improve fracturing-fluid transport properties, hold openfractures in far field from the borehole, and reduce cost because ofproppant replacement. Embodiments generate proppant (or proppant-likematerial) in situ through the oxidation of formation pyrite to formjarosite. The geological formation may be hydraulically fractured withfracturing fluid containing an oxidizer that converts pyrite to jarositeas the fracturing fluid permeates the reservoir. Jarosite formed in thefractures generated by the fracturing process may hold the fracturesopen allowing hydrocarbons to flow during production of the hydrocarbon.Such can decrease the amount of conventional proppant utilized whilealso promoting hydrocarbon flow from deeper (far field) in thereservoir.

Certain embodiments provide for jarosite group minerals grown in situ inrock formations upon treatment of the rock with an oxidizer and asulfate source. The sulfate source can be in conjunction with theoxidizer. The sulfate source can be, for example, sulfate or persulfatesalts of sodium, potassium, or ammonium. The sulfate source can besulfur-bearing compounds that can be oxidized to sulfate such assulfite, pyrosulfate, and thiosulfate. The sulfur source can be sulfuricacid or alkali and alkali earth salts of hydrogen sulfate. The oxidizercan be, for example, alkali and alkali earth salts of bromate orchlorate. The jarosite group minerals formed can be, for example,jarosite, natrojarosite, ammoniojarosite, or hydronium jarosite, or anycombinations thereof.

A specific application may treat formation rock bearing pyrite andkerogen with oxidizer. As the oxidizer acts on the kerogen, the oxidizergenerally also oxidizes the pyrite in the kerogen to Fe³⁺ and SO₄ ²⁻.The Fe³⁺ and SO₄ ²⁻ in turn precipitate as jarosite. After the kerogenhas been degraded and removed, jarosite may remain in the voids thekerogen previously occupied. The jarosite may also form at thekerogen-rock interface providing the former kerogen channels withadditional jarosite proppant. The jarosite can also deposit on thesurface of the rock beyond the kerogen voids. Jarosite may also formwhere the oxidizing fluid contacts formation pyrite unassociated withkerogen. The jarosite formed is generally stable under the pressures andtemperatures of a petroleum reservoir or source rock and thus may be abeneficial proppant substitute. The jarosite or jarosite matrix producedmay typically be a porous structure that permits the flow of producedhydrocarbons.

Turning now to the drawings, FIG. 1 is an image of a kerogen-rich shalesample 100 containing pyrite minerals of both euhedral 102 andframboidal 104. Pyrite is an iron sulfide (FeS₂) mineral that can beprevalent in unconventional source rock reservoirs (sedimentary rock).The mineral can be present in two different forms: euhedral 102 andframboidal 104. In the euhedral 102 case, the pyrite mineral has definedfacets. Framboidal 104 pyrites, by contrast, are clusters of smallpyrite crystals. FIG. 1 shows an example of a kerogen-rich shale sample100 containing both types 102, 104 of pyrite.

FIGS. 2A and 2B illustrate the arrangement of iron 202 and sulfur 204atoms in mackinawite 200 (FIG. 2A) and pyrite 206 (FIG. 2B),respectively. FIG. 2A is a crystal structure of the iron-sulfidemackinawite 200. FIG. 2B is a crystal structure of the iron-sulfidepyrite 206. The illustration of crystal structures of mackinawite 200and pyrite 206 depicts 2×2 unit cells with iron 202 and sulfur 204.Pyrite is generally an insoluble mineral. Concentrated acid or basegenerally cannot dissolve the pyrite. The insolubility of pyrite 206 isrelated to the structure of the pyrite. The pyrite structure is eachiron (Fe) 202 is coordinated to six sulfur (S) 204 atoms in anoctahedral arrangement. By contrast, other forms of iron sulfide (forexample, marcasite) are soluble in acid. The 1:1 stoichiometry of Fe:Sin marcasite differs from the 1:2 stoichiometry of Fe:S in pyrite.Further, iron 202 atoms in the mackinawite 200 structure aretetrahedrally coordinated to sulfur 204 atoms. Whereas mackinawite 200forms a layered structure, pyrite 206 is composed of a packed lattice.There are forms of iron sulfide other than mackinawite 200 and pyrite206. Pyrite 206 is the generally the most insoluble and stable structureof iron sulfide. Further, pyrite 206 can be a predominant iron sulfidemineral that is present in hydrocarbon-bearing geological formations.

Because pyrite generally cannot be directly dissolved, a presentapproach is to oxidize the iron and sulfur of the pyrite to form solublespecies. As pyrite is oxidized, Fe²⁺ is converted to Fe³⁺ and sulfide S₂²⁻ is converted to 2SO₄ ²⁻. These generated ions are soluble in aqueousfluid. The elevated temperature of the reservoir provides thehydrothermal conditions for the Fe³⁺ and SO₄ ²⁻ to react to formjarosite. Jarosite is a basic hydrous sulfate of potassium and iron witha chemical formula of KFe³⁺ ₃(OH)₆(SO₄)₂. As indicated, this sulfatemineral may be formed by the oxidation of iron sulfides. The mineralgroup of jarosite consists of Fe³⁺ and SO₄ ²⁻ but can vary in otheraspects of its composition. The composition of jarosite isKFe₃(OH)₆(SO₄)₂ but the potassium cation can be substituted with Na(giving natrojarosite), hydronium H₃O⁺ (giving hydroniumjarosite), orammonium NH₄ ⁺ (giving ammoniojarosite). This mineral group may becharacterized as a solid solution series. The potassium can also besubstituted with other metal cations such as vanadium, lead, lithium,and antimony.

FIG. 3 is a crystal structure of jarosite 300. The depiction shows 2×2unit cells. The jarosite 300 includes octahedral Fe³⁺ layers andtetrahedral SO₄ ²⁻ layers. Iron atoms 302 center the octahedral. Sulfuratoms 304 center the tetrahedra. The alternating tetrahedra andoctahedra are connected by oxygen atoms 306. Countercations 308 (forexample, potassium) fill the interstitial spaces.

Embodiments provide the hydrothermal synthesis of jarosite in thegeological formation and the associated or subsequent precipitation ofthe jarosite on the fracture faces as microproppant and nanoproppant.Embodiments are suited for fracturing fluids containing oxidizer. As thefracturing fluid acts on kerogen and pyrite, the rock may become moreprone to fracture. The jarosite proppant can form in the formerkerogen-containing rock regions as well as on the fracture surfacesformed in the hydraulic fracturing into which the oxidizer-bearingfracturing fluid intrudes. The jarosite proppant may facilitatehydrocarbons to flow (be produced) from far field within the formation.In certain embodiments with the in-situ formed jarosite, the amount ofsurface-sourced proppant in the fracturing treatment may be reduced andthus fracturing cost reduced in some implementations.

An embodiment of generating jarosite in the fractures is via performinghydraulic fracturing with a frac fluid (fracturing fluid) containingboth Fe³⁺ and SO₄ ²⁻. The Fe³⁺ and SO₄ ²⁻ at room temperature areunreactive but at wellbore temperatures react to form jarosite. Thepumped frac fluid having both Fe³⁺ and SO₄ ²⁻ may generate jarosite as aproppant in the microfractures and nanofractures before surface-sourcedproppants (for example, sand-based proppants) are added (if needed). Thefrac fluid may contain Fe²⁺ that is oxidized to Fe³⁺ when anencapsulated oxidizer is released downhole.

Embodiments generate proppant directly in fractures via treatment of akerogen-containing rock with an oxidizer-containing fracture fluid. Inimplementations, proppant forms during the oxidation of pyrite containedin the kerogen and the rock. The jarosite proppant forms in the channelsformerly occupied by kerogen and in the fractures opened during the“fracking process.” Jarosite is stable at typical reservoir pressuresand temperatures and permeable to produced hydrocarbon flow from withinthe reservoir. In a particular embodiment, the forming of the jarositeis completed within two hours. Two hours may be a typical time for afrac job. By adjusting the treatment conditions, jarosite of varyingheights and geometries can be grown. The permeability of the jarositematrix can be similarly tuned to increase or optimize the subsequentproduced hydrocarbon flow. The treatment conditions adjusted can includepH, concentration of reagents, sulfur source, and well conditions.

Conventional proppant composed of sand or man-made ceramics is flowedinto the fractures generated by the hydraulic fracturing or “fracking”process. The fracture size maintained may be related to the grain sizeof the sand and how individual grains of sand interact in a channel.Sand-based proppants can generate fines which can decrease permeability.Other surface-supplied proppant may present similar issues. In contrast,present embodiments give the in-situ formation of proppant inmicrofractures and nanofractures where sand has not traditionallypenetrated. This in-situ forming of proppant provides proppant to suchfractures and thus may allow hydrocarbon recovery via microfracturesgenerated in the fracturing process. Such may lead to a greater percentof oil recovery from the reservoir.

A related embodiment is fracturing with a fracturing fluid containingFe³⁺ and SO₄ ²⁻ in which these ions may be incorporated into thefracturing fluid at the Earth surface. These ionic species generally donot react except at elevated temperatures such as the temperature of thegeological formation. Therefore, upon fracking, jarosite may be formed(from these ions) in the resulting fractures with the jarosite servingas a proppant to facilitate hydrocarbon exit from the geologicalformation. In certain embodiments, the formation of the jarosite fromthe ions in the fracturing fluid is without oxidation of the rock,kerogen, or pyrite in the geological formation.

FIG. 4 is sequence diagram of a well 400 in a geological formation. FIG.4 illustrates a technique by which the jarosite 402 is formed in thegeological formation. The sequence diagram is a schematic demonstratingthe generation of jarosite proppant 402 upon pumping a fracturing fluid404 containing oxidizer into the pyrite-bearing formation. The sequence401 shows the forming of in-situ jarosite proppant 402 in a hydraulicfracture 403 where oxidizing fracturing fluid 404 penetrates and reactswith the geological formation. The fracture 403 has a length 405 andwidth 407.

To generate the fracture 403, the fracturing fluid 404 (and anyconventional proppant) is injected into the well via a wellbore 406 tohydraulically fracture the geological formation. The wellbore 406 isdepicted as a circular cross-section. The fracture 403 is formedpropagating out from the wellbore 406. In the illustrated embodiment,the fluid 404 front near the fracture tip 408 comes in contact withpyrite 410 in the formation.

The pyrite 410 (for example, pyrite framboid and including kerogen ifpresent) is oxidized 412 forming the soluble species Fe³⁺ and SO₄ ²⁻. Athreshold concentration of these Fe³⁺ and SO₄ ² species (forhydrothermal synthesis) is reached in the surrounding aqueous fluid (forexample, the oxidizing fracturing fluid 404).

Hydrothermal synthesis occurs to form jarosite that precipitates formingcrystallites. The crystallites formed are the in-situ jarosite proppant402 that may be nanoproppant and microproppant. Thus, the Fe³⁺ and SO₄²⁻ formed from the oxidizing undergoes hydrothermal synthesis atwellbore temperature to form the in-situ jarosite proppant 402. In theillustrated implementation, a surface-sourced proppant 414 may be pumpedinto the fracture 403 at near wellbore.

Example 1

The Examples presented are given only as examples and not meant to limitthe present techniques. In Example 1, shale rock was treated with asolution of 10 milliliters (ml) of 13 millimolar (mM) NaBrO₃, 8.7 mM(NH₄)₂S₂O₈, and 0.27 molar (M) KCl for 20 hours at 150° C. Jarositeformation was observed on the exposed faces of the shale rock (see FIG.5).

FIG. 5 is images 500 of the shale treated with the oxidizing solution inExample 1. The images 500 are scanning electron microscope (SEM) images.The image (a) 502 and image (b) 504 are images of the shale rock beforethe solution was applied. The image (c) 506 and image (d) 508 are imagesof the shale rock after the solution was applied and thus depict theshale rock as treated. The inset image is a magnified portion depictingjarosite grains 510 in the treated shale rock.

FIG. 6A is an SEM image 600 of the jarosite 601 produced on the shalerock in Example 1. The image 600 is magnified as compared to images 506,508 of FIG. 5.

FIG. 6B is the corresponding spectrum 602 for the jarosite 601 produced.The spectrum 602 is by energy dispersive x-ray spectroscopy (EDS) and isin agreement with a jarosite composition. The EDS spectrum 602 is a plotof x-ray counts 604 in counts per second per electron-volt (cps/eV)versus energy 606 in kiloelectron volts (keV).

Example 2

In Example 2, 100 milligrams (mg) of FeS₂ (pyrite) were treated withsolutions of 0.1M NaBrO₃ at various temperatures. Jarosite formed andprecipitated as the temperature increased. Table 1 gives the molar (M)concentrations of the soluble species Fe³⁺ and SO₄ ²⁻ formed in theoxidation as a function of reaction temperature. The last column inTable 1 is the molar ratio of SO₄ ²⁻ to Fe³⁺.

TABLE 1 [Fe³⁺] and [SO₄]²⁻ as a function of reaction temperature Temp[Fe³⁺] [SO₄ ²⁻] ° C. 10⁻⁴ M 10⁻⁴ M [SO₄ ²⁻]:[Fe³⁺] 20 1.2 9.8 8 50 0.88.9 11 75 0.4 9.6 26 100 0.8 12.5 16 120 0.2 8.7 52 150 0.2 10.1 52

FIG. 7A is a plot 700 of iron concentration 702 (mg per liter or mg/L)versus reaction temperature 704 (° C.). The points 706 are the measuredvalues of iron concentration in the oxidation as a function of reactiontemperature.

FIG. 7B is a plot 708 of sulfate concentration 710 (mg/L) versusreaction temperature 704 (° C.). The points 712 are the measured valuesof sulfate concentration in the oxidation as a function of reactiontemperature.

Thus, FIGS. 7A and 7B give Fe³⁺ concentration and SO₄ ²⁻ concentration,respectively, as a function of reaction temperature. Jarosite formationis seen by the decrease in iron concentration with increasingtemperature in FIG. 7A.

FIG. 8A is an image 800 of the residual solids 802 from the bromatetreatment of pyrite in Example 2. The portion 804 has remnants ofunreacted pyrite. The residual solids 802 is the resulting precipitateof the oxidation of Example 2 and as associated with the decrease iniron concentration depicted in FIG. 7A, which confirmed Jarositeformation.

FIG. 8B results further confirm the Jarosite formation by powder x-raydiffraction (PXRD) of the resulting precipitate, which shows sodiumhydronium jarosite. FIG. 8B is a PXRD spectrum 806 of the residualsolids 802. The scattering angle 808 (or diffraction angle) is 2-thetain degrees. The spectrum 806 shows portions 810 that are sodiumhydronium jarosite such as Na_(x)(H3O)_(1-x)Fe₃(SO₄)₂(OH)₆. The spectrum806 shows portions 812 that are pyrite (unreacted).

Typically, resin-coated sand may be employed as the proppant. The sizeof the sand utilized generally limits permeation into the smallfractures. Further, as mentioned, the use of sand is known to generatesand fines which decrease permeability. Present embodiments can replacesome of the pumping of proppants including small mesh microproppants(for example, 100 mesh or 150 μm, 200 mesh or 75 μm, 400 mesh or 35 μm,635 mesh or 20 μm) by having in-situ grown jarosite maintaining fracturepaths open for hydrocarbon production.

As discussed, an advantage of this proppant replacing technology mayrelate to “proppant transport” properties. The transport property ofproppant is a property where the proppant is expected to be suspendedwithin the treatment fluid without settling due to weight of theproppant. A lightweight proppant has a better transport property than aheavier proppant. Present embodiments eliminate or reduce the need forthe transport property at least for the part of the implementation wherethe traditional proppant is replaced. Fracture treatment fluid notcontaining proppant particles can be more efficient in transport throughthe fracture network. Implementations generate proppants (in themicrofractures and nanofractures) where sand generally cannot go.Jarosite formation whether by pyrite oxidation or directed formation(for example, adding Fe³⁺ and SO₄ ²⁻ to the fracturing fluid) can reducecosts and enhance productivity in fracturing applications.

An additional advantage of a jarosite layer grown on fracture faces maybe that of preventing, reducing, or mitigating proppant embedment.Proppant embedment can occur due to the mismatch in mechanicalproperties of the geological formation and the proppant (for example,harder proppant on a softer surface of the fracture). As discussed,proppant embedment can lead to a reduction in fracture width and hence areduction in hydrocarbon conductivity. Controlled growth of the jarositelayer may create a hard surface to the matrix that may reduce thepossibility of proppant embedment.

The present techniques recognize jarosite as a beneficial material andprovide for in-situ generated proppant for fracking purposes. Thetechniques may generate the proppant from material in the geologicalformation. Fracturing with an oxidizer-containing fluid to generateproppant in situ is provided.

While the present discussion has focused at times on formation ofjarosite mineral from pyrite rock, minerals that are not jarosite may beformed in-situ from the rock (including rock not pyrite) to act as aproppant. For example, the mineral formed in-situ as proppant mayinclude hematite, lepidocrocite, or ferrihydrite, or any combinationsthereof. The type of mineral grown (as proppant) from the rock in thegeological formation may depend on the rock type. The rock can includesiderite, pyrrhotite, chlorite group minerals, chamosite, illite,marcasite, mica, or ankerite, or any combinations thereof. Lastly, theincorporation of an additive including an oxidizer or ions into fluidfor in-situ formation of the mineral or proppant can be included in apumped treatment fluid after fracturing and without hydraulic fracturingoccurring during in-situ forming of the mineral or proppant.

FIG. 9 is a well site 900 having a wellbore 902 formed through the Earthsurface 904 into a geological formation 906 in the Earth crust. Thewellbore 902 can be vertical, horizontal, or deviated. The wellbore 902can be openhole but is generally a cased wellbore. The annulus betweenthe casing and the formation 906 may be cemented. Perforations may beformed through the casing and cement into the formation 906. Theperforations may allow both for flow of fracturing fluid into thegeological formation 906 and for flow of produced hydrocarbon from thegeological formation 906 into the wellbore 902.

The well site 900 may have a hydraulic fracturing system including asource of fracturing fluid 908 at the Earth surface 904 near or adjacentthe wellbore 902. The fracturing fluid 908 may also be labeled as fracfluid, fracing fluid, or fracking fluid. The fracturing fluid 908 sourcemay include one or more vessels holding the fracturing fluid 908. Thefracturing fluid 908 may be stored in vessels or containers andincluding on trucks in some implementations. In certain implementations,the fracturing fluid 908 is slick water which may be primarily water(for example, generally at least 98.5% water by volume). The fracturingfluid 908 can also be gel-based fluids. Moreover, the fracturing fluid908 can be prepared from seawater. In addition, the fracturing fluid 908can include polymers and surfactants. Other common additives may includehydrochloric acid, friction reducers, emulsion breakers, andemulsifiers.

The hydraulic fracturing system at the well site 900 may include motivedevices such as one or more pumps 910 to pump (inject) the fracturingfluid 908 through the wellbore 902 into the geological formation 906.The pumps 910 may be, for example, positive displacement and arranged inseries or parallel. Again, the wellbore 902 may be a cemented casedwellbore and have perforations for the fracturing fluid 908 to flow(injected) into the formation 906. In some examples, the speed of thepumps 910 may be controlled to give desired flow rate of the fracturingfluid 908. The system may include a control component 912 to modulate ormaintain the flow of fracturing fluid 908 into the wellbore 902 for thehydraulic fracturing and treatment to form jarosite or proppant in situ.The control component 912 may be, for example, a control valve(s). Insome implementations, the control component 912 may be the pump(s) 910as a metering pump in which speed of the pump 910 is controlled to givethe specified flow rate of the fluid 908. The set point of the controlcomponent 912 may be specified or driven by a control system 914.

In accordance with present embodiments, the fracturing fluid 908 mayinclude an additive 909 to form jarosite or proppant in situ in thegeological formation, as discussed earlier. In certain embodiments, theadditive 909 is an oxidizer (for example, bromate) and may include asulfate source (for example, persulfate). In those embodiments, thefracturing fluid 908 having the oxidizer may oxidize pyrite in thegeological formation 906, as discussed. In other embodiments, theadditive 909 may include iron Fe³⁺ ions and sulfate SO₄ ²⁻ ions for thetreating of rock and generation of jarosite in situ with little or nooxidation downhole. In other words, the jarosite may form (for example,via hydrothermal synthesis) and precipitate in situ from the ions in thefracturing fluid 908 via the conditions (for example, temperature) ofthe formation 906.

The oxidizing or treating of the pyrite or rock via the additive 909 maygrow jarosite in fractures in the geological formation 906. The formedjarosite may act as a proppant, as discussed. The formed proppant may beformed in microfractures and far field into the fractures. The formedjarosite may be formed as a layer (for example, less than 50 μmthickness) on fracture faces to prevent or reduce embedment oftraditional proppant. The additive 909 may include bromate, persulfate,Fe³⁺, or SO₄ ²⁻, or any combinations thereof. In some implementations,the water to prepare the fracturing fluid 908 may be seawater whichtypically has SO₄ ²⁻ content.

For the fracturing fluid 908 having the additive 909 including anoxidizer, the oxidizer may include bromate ions BrO₃ ⁻ or chlomate ionsClO₃ ⁻, or both. For instance, the oxidizer may include an alkali saltof bromate or chlorate (for example, sodium bromate or NaBrO₃, potassiumbromate or KBrO₃, ammonium bromate or NH₄BrO₃, sodium chlorate orNaClO₃, potassium chlorate or KClO₃, ammonium chlorate or NH₄ClO₃), oran alkali earth metal salt of bromate or chlorate (for example,magnesium bromate or Mg(BrO₃)₂, calcium bromate or Ca(BrO₃)₂, bariumbromate or Ba(BrO₃)₂, magnesium chlorate or Mg(ClO₃)₂, calcium chlorateor Ca(ClO₃)₂, barium chlorate or Ba(ClO₃)₂), or any combinationsthereof. Alkali earth metals include beryllium (Be), magnesium (Mg),calcium (Ca), strontium (Sr), barium (Ba), and radium (Ra).

The oxidizer may be utilized with a sulfur source or sulfate source.Thus, the additive 909 may include the sulfur source or sulfate source.Therefore, the fracturing fluid 908 may include the oxidizer and thesulfate source. In some instances, the sulfate source may becharacterized as an additional or supplemental oxidizer. The sulfatesource may include sulfate ions SO₄ ²⁻ and persulfate ions SO₅ ²⁻ orS₂O₈ ²⁻. The sulfate source may include a sulfate salt (or persulfatesalt) of sodium, potassium, or ammonium. For example, the sulfate sourcemay include sodium sulfate (Na₂SO₄), sodium persulfate (Na₂S₂O₈),potassium sulfate (K₂SO₄), potassium persulfate (K₂S₂O₈), ammoniumsulfate ((NH₄)₂SO₄), or ammonium persulfate ((NH₄)₂S₂O₈), or anycombinations thereof. The sulfate source can be sulfuric acid orhydrogen sulfate ions HSO₄ ⁻, or a combination thereof. The sulfatesource may include an alkali salt or alkali earth salt of hydrogensulfate, such as sodium hydrogen sulfate (sodium bisulfate or NaHSO₄),potassium hydrogen sulfate (potassium bisulfate or KHSO₄), ammoniumhydrogen sulfate (ammonium bisulfate or (NH₄)HSO₄), magnesium hydrogensulfate (magnesium bisulfate or Mg(HSO₄)₂), calcium hydrogen sulfate(calcium bisulfate or Ca(HSO₄)₂), barium hydrogen sulfate (Ba(HSO₄)₂),or any combinations thereof. Alternatively, the sulfate source mayinclude sulfur-bearing compounds that can be oxidized to sulfate such assulfite, pyrosulfate, thiosulfate, or any combinations thereof.

In operation for certain implementations, the amount of the additive 909incorporated into the fracturing fluid 908 may be modulated via acontrol component 911. The control component 911 may be a control valveor metering pump. The amount of additive 909 added to the fracturingfluid 908 may be altered to adjust concentration of the additive 909 inthe fracturing fluid 908 to adjust the amount or property (for example,density) of jarosite or jarosite matrix formation in the geologicalformation 906. The composition of the additive 909 may be changed duringthe hydraulic fracturing to adjust a property of the jarosite formed.The control component 911 may also provide for starting and stoppingaddition of the additive 909 to the fracturing fluid 908. In particularimplementations, the additive 909 may generally be included in thefracturing fluid 908 during a first portion of the hydraulic fracturingjob, such as in the range of the first 1 to 4 hours (for example, first2 or 3 hours). In certain implementations, the additive 909 is includedin the fracturing fluid 908 prior to addition of proppant to thefracturing fluid 908.

The hydraulic fracturing system at the well site 900 may have a sourceof proppant (for example, sand) which can include railcars, hoppers,containers, or bins having ceramic proppants or sand of differing meshsize (particle size). The source of proppant may be at the Earth surface904 near or adjacent the wellbore 902. The fracturing fluid 908 mayinclude proppant. In some examples, the proppant may be added (forexample, via gravity) to a conduit conveying the fracturing fluid 908such as at a suction of a fracturing fluid pump 910. The hydraulicfracturing system may include a feeder or blender to receive a proppantand discharge the proppant into a conduit conveying the fracturing fluid908. Thus, the fracturing fluid 908 may be a slurry that is acombination of the fracturing treating fluid and proppant. For instanceswhen proppant is not added to the fracturing fluid, the fracturing fluid908 entering the wellbore 902 for the hydraulic fracturing and treatingmay be the fracturing fluid without proppant. Fracturing fluid of lowviscosity (for example, less than 100 centipoise (cP)) or high viscosity(for example, greater than 100 cP) may be employed in the hydraulicfracturing.

The frac rates may include a clean rate that is a flow rate offracturing fluid 908 without proppant. The frac rates can include aslurry rate that may be a flow rate of the fracturing fluid 908 asslurry of proppant and fracturing fluid. In some implementations, thefracturing fluid in the slurry can be a thicker or more viscousfracturing fluid having a viscosity greater than 100 cP. In particularimplementations, the frac rates or parameters adjusted may include atleast two variables which are fracturing-fluid pump(s) 910 rate andproppant (for example, sand) concentration in the fracturing fluid 908.Frac operations can be manual and guided with controllers and software.

The control system 914 may direct operation of the hydraulic fracturingsystem including the addition of the additive 909 to the fracturingfluid 908 in particular. The control system 914 may have one or morecontrollers. The control system 914 may include a hardware processor 916and memory 918 storing code 920 (for example, logic and instructions)executed by the processor to direct operations such as specifying theset point of the control component 911 to maintain or adjust a propertyof the jarosite formed. The control system 914 responsive, for example,to the timing of the hydraulic fracturing may send an alert to changethe composition of the additive 909 to affect a property of the jarositeformed. In some implementations, the control system 914 may direct anadditive system (not shown) to alter the composition of the additive909.

The processor 916 may be one or more processors, and may have one ormore cores. The hardware processor(s) 916 may include a microprocessor,a central processing unit (CPU), a graphics processing unit (GPU), orother circuitry. The memory 918 may include volatile memory (forexample, cache and random access memory or RAM), nonvolatile memory (forexample, hard drive, solid-state drive, and read-only memory or ROM),and firmware. The control system 914 may include a field computer,remote computer, laptop computer, a desktop computer, a programmablelogic controller (PLC), distributed control system (DCS), and controlcard or circuitry.

The control system 914 or associated computing system may direct the insitu formation of jarosite or proppant and is therefore unconventional.

The control component 911 (for example, as directed by the controlsystem 914) may adjust the timing of the injected fracturing treatmentfluid 908 as having the additive 909 to generate a jarosite matrixhaving a “spatial gradient” that provides a variance of permeabilitybetween near wellbore to far-field fracturing. The timing orconcentration of the additive 909 in the fracturing fluid 908 may beadjusted for growing jarosite in-situ of varying heights and geometries,for example, at larger mesh in near wellbore (jarosite>150 μm) tosmaller mesh in far-field (jarosite<150 μm) fracturing applications. Ina particular implementation, the control system 914 may direct thecontrol component 911 to alter flow rate and thus adjusting thecomposition of the treatment fluid 908 to generate a jarosite matrix ofvarying packing density to provide a varying permeability from nearwellbore to far-field fracturing application.

An embodiment is a hydraulic fracturing system including a vesselholding a fracturing fluid. The system includes a control component (forexample, control valve or metering pump) to modulate an addition rate ofan additive (for example, an oxidizer or iron ions) to the fracturingfluid in the vessel. For some implementations with the frac fluidprepared from seawater, an adequate amount of sulfate ions may alreadyexist in the frac fluid and, therefore, iron ions are incorporated intothe frac fluid as a component of aforementioned additive. In otherexamples, sulfate ions may be incorporated as a component of theadditive. In yet other examples, an oxidizer is incorporated and whichmay be, for instance, bromate or chlorate. The system includes a pump(or plurality of pumps) to provide the fracturing fluid from the vesselthrough a wellbore into a geological formation to hydraulically fracturethe geological formation to generate fractures in rock in the geologicalformation. The pump may be, for example, a positive displacement pump. Acontrol system adjusts a set point of the control component to change aconcentration of the additive in the fracturing fluid in response to atiming of the hydraulic fracturing and to alter a property of a jarositematrix formed in the fractures via the fracturing fluid. In oneimplementation, the property adjusted is packing density of the jarositematrix.

FIG. 10 is a method 1000 of forming material (for example, jarosite) ina geological formation. The method may including forming the material asproppant in situ in the geological formation, such as in fractures inrock in the geological formation. The proppant may aid in maintainingfractures open in the geological formation.

At block 1002, the method includes incorporating an additive (forexample, additive 909) in frac fluid for forming the material in thegeological formation. As discussed, the additive may include anoxidizer, sulfate source, Fe³⁺ ions, or SO₄ ²⁻ ions, or any combinationsthereof. The timing or amount of additive may be adjusted to alterproperties of the jarosite or proppant formed in situ in the geologicalformation.

At block 1004, the method includes injecting frac fluid (which may havethe additive) through a wellbore into the geological formation. Forexample, the frac fluid may be pumped into the wellbore. For thewellbore as a cemented cased wellbore, perforations through the casingand cement may facilitate introduction or injection of the frac fluidfrom the wellbore into the geological formation.

At block 1006, the method includes hydraulically fracturing thegeological formation with the frac fluid. The fracturing may be toincrease the subsequent production of hydrocarbon (for example, crudeoil and natural gas) from the geological formation. The fracturing mayinclude primary fractures and smaller secondary fractures. The fracturesmay include microfractures. The hydraulic fracturing may include theintroduction of traditional proppant.

At block 1008, the method includes forming material or mineral (forexample, jarosite, proppant, or jarosite proppant) in the geologicalformation via the frac fluid. As discussed, the frac fluid may formjarosite proppant or a jarosite layer in fractures in the geologicalformation. The jarosite may precipitate from the frac fluid onto rock inthe geological formation, such as onto fracture faces.

In certain embodiments, the frac fluid has an oxidizer (theaforementioned additive) to oxidize pyrite in the geological formationto form the jarosite. The frac fluid may also include a sulfate sourceassociated with the oxidizer. The oxidizer (and sulfate source) oxidizethe pyrite to generate Fe³⁺ ions and SO₄ ²⁻ ions. The Fe³⁺ ions and SO₄²⁻ ions may react and precipitate as jarosite.

In other embodiments, the frac fluid has Fe³⁺ ions and SO₄ ²⁻ ionsincorporated into the frac fluid at the Earth surface to form thejarosite in situ in the geological formation such as in the fractures.For some implementations with the frac fluid prepared from seawater, anadequate amount of SO₄ ²⁻ ions may already exist in the frac fluid andtherefore, Fe³⁺ ions are incorporated into the frac fluid as theaforementioned additive.

At block 1010, the method includes acting on kerogen by the frac fluidif kerogen is present in the geological formation. For implementationswith the frac fluid including an oxidizer, the frac fluid may degradeand remove kerogen from rock in the geological formation. Thus, in thoseinstances, jarosite may form in voids in the rock provided by theremoval of kerogen.

An embodiment is a method of forming proppant in situ in a geologicalformation, including injecting a frac fluid through a wellbore into thegeological formation, and hydraulically fracturing the geologicalformation with the frac fluid to generate fractures in the geologicalformation. The method includes forming, via the frac fluid andhydrothermal synthesis, the proppant in situ in the fractures in thegeological formation. The proppant may be formed from rock in thegeological formation or from ions in the frac fluid, or a combinationthereof. The forming may involve forming the proppant from pyrite in thegeological formation. The frac fluid may include an oxidizer, and wherethe forming of the proppant (for example, jarosite) involves oxidizingthe pyrite via the frac fluid to give iron ions and sulfate ions in thefrac fluid and to grow the proppant on rock in the geological formation.The forming of the proppant may involve precipitating the proppant fromthe frac fluid as crystallites such that the proppant is deposited onfaces of the fractures. The proppant may be formed from iron ions andsulfate ions in the frac fluid. The proppant may be a jarosite mineral.

Another embodiment is a method of forming proppant in situ in ageological formation, including pumping a fracturing fluid through awellbore into the geological formation, and hydraulically fracturing thegeological formation with the frac fluid to generate fractures in thegeological formation. The method includes precipitating the proppantfrom the fracturing fluid on rock in the geological formation. In someimplementations, the fracturing fluid includes Fe³⁺ ions and SO₄ ²⁻ions. In examples, the precipitating of the proppant on the rockcomprises depositing the proppant as crystallites on faces of thefractures. The method may include oxidizing the rock in the geologicalformation via the fracturing fluid having an oxidizer. The rock mayinclude pyrite and where the proppant formed includes or is a jarositegroup mineral.

Yet another embodiment is a method of forming a mineral in a geologicalformation, including injecting a frac fluid through a wellbore into thegeological formation and forming, via the frac fluid, the mineral onrock in the geological formation. The rock may include pyrite. The rockcan include pyrite, siderite, pyrrhotite, chlorite group minerals,chamosite, illite, marcasite, mica, ankerite, or other minerals, or anycombinations thereof. The injecting of the frac fluid may involvepumping the frac fluid from the Earth surface. The forming of themineral may include precipitating the mineral on fracture faces in thegeological formation as a proppant (for example, having a particle sizeless than 150 μm). The mineral may include jarosite, hematite,lepidocrocite, or ferrihydrite, or any combinations thereof. The mineralformed may be jarosite. The jarosite formed may be a jarosite matrix.The jarosite may include a jarosite solid solution series. The jarositemay include natrojarosite, hydroniumjarosite, or ammoniojarosite, or anycombinations thereof. The method may include hydraulically fracturingthe geological formation with the frac fluid to generate fractures inthe geological formation. The forming of the jarosite on the rockincludes forming the jarosite in the fractures. The jarosite formed inthe fractures may include jarosite particles (for example, having aparticle size of less than 150 μm) and with the jarosite particlesacting as a proppant in the fractures. The forming of the jarosite mayinclude forming, via the frac fluid, the jarosite as a proppant in afracture tip portion of a hydraulic fracture in the geologicalformation. Moreover, the forming of the jarosite may involve oxidizingpyrite in the geological formation with the frac fluid. The oxidizing ofthe pyrite may include oxidizing the pyrite to Fe³⁺ and SO₄ ². Thepyrite is generally an iron sulfide mineral FeS₂. The oxidizing of thepyrite can include converting Fe²⁺ in the pyrite to Fe³⁺ and convertingsulfide S₂ ²⁻ in the pyrite to 2SO₄ ²⁻. The frac fluid may have anoxidizer including bromate ions or chromate ions, or a combinationthereof. The frac fluid may have an oxidizer including an alkali salt ofbromate, an alkali salt of chlorate, an alkali earth metal salt ofbromate, or an alkali earth metal salt of chlorate, or any combinationsthereof. The frac fluid may have an oxidizer and a sulfate sourceincluding sulfate ions SO₄ ²⁻ or persulfate ions S₂O₈ ²⁻, or acombination thereof. The frac fluid may have an oxidizer and a sulfatesource. The sulfate source can include a sulfate salt of sodium,potassium, or ammonium, or a persulfate salt of sodium, potassium, orammonium, or any combinations thereof. The forming of the jarosite mayinvolve reacting Fe³⁺ and SO₄ ²⁻ and where a temperature of thegeological formation provides a hydrothermal condition for the reacting.The forming of the jarosite may include hydrothermal synthesis of thejarosite and precipitation of the jarosite on the rock. Theprecipitation on the rock may include precipitation of the jarosite onfracture faces as a microproppant or nanoproppant, or both. The methodmay include the frac fluid degrading and removing kerogen from the rock.The removal of the kerogen may create voids in the rock. The forming ofthe jarosite may include growing jarosite in the voids. The forming ofthe jarosite may include depositing jarosite on a surface of the rockoutside of the voids.

Yet another embodiment is a method of forming a jarosite group mineralin a geological formation, including pumping a fracing fluid through awellbore into the geological formation and hydraulically fracturing thegeological formation with the fracing fluid to generate fractures in thegeological formation. The fracing fluid may include seawater. The methodincludes synthesizing the jarosite group mineral from iron ions andsulfate ions in the fracing fluid via temperature of the geologicalformation. The method includes precipitating the jarosite group mineralto deposit the jarosite group mineral as a crystallite on faces of thefractures. The precipitating may include forming the jarosite groupmineral as a proppant in the fractures. The precipitating may includeforming a layer of the jarosite group mineral on the faces of thefractures. In one implementation, the layer has a thickness of less than30 μm. The method may include oxidizing pyrite in the geologicalformation via the fracing fluid having an oxidizer to give respectivethreshold concentrations of the iron ions and sulfate ions in thefracing fluid for the synthesizing (for example, involving hydrothermalsynthesis) of the jarosite group mineral. The method may includeincorporating the iron ions and the sulfate ions in the fracing fluid atthe Earth surface outside of the wellbore.

A number of implementations have been described. Nevertheless, it willbe understood that various modifications may be made without departingfrom the spirit and scope of the disclosure.

What is claimed is:
 1. A method of forming proppant in situ in fracturesin a geological formation, comprising: providing a frac fluid through awellbore into the geological formation; hydraulically fracturing thegeological formation with the frac fluid to generate the fractures inthe geological formation; and forming the proppant in situ in thefractures by forming mineral in the fractures via hydrothermal synthesisof the mineral from ions in the frac fluid, wherein the proppant is themineral.
 2. The method of claim 1, wherein the ions comprise iron Fe³⁺ions.
 3. The method of claim 2, wherein the ions comprise sulfate SO₄ ²⁻ions.
 4. The method of claim 1, wherein the ions comprise ions receivedinto the frac fluid by oxidizing, via the frac fluid, rock in thegeological formation.
 5. The method of claim 4, wherein the ionsreceived into the frac fluid comprise iron Fe³⁺ ions by conversion ofiron Fe²⁺ in the rock via the oxidizing.
 6. The method of claim 5,wherein the ions received into the frac fluid comprise sulfate SO₄ ²⁻ions by conversion of sulfide S₂ ²⁻ in the rock via the oxidizing. 7.The method of claim 4, wherein the rock comprises pyrite, siderite,pyrrhotite, chlorite group minerals, chamosite, illite, marcasite, mica,or ankerite, or any combinations thereof.
 8. The method of claim 4,wherein the rock comprises pyrite.
 9. The method of claim 1, wherein theions comprise ions added to the frac fluid at Earth surface.
 10. Themethod of claim 9, wherein the ions added to the frac fluid comprisesiron Fe³⁺ ions.
 11. The method of claim 9, wherein the ions added to thefrac fluid comprises sulfate SO₄ ²⁻ ions.
 12. The method of claim 1,wherein the ions comprise ions from a sulfate source added to the fracfluid at Earth surface or from oxidation of the sulfate source added tothe frac fluid at the Earth surface, or a combination thereof.
 13. Themethod of claim 1, wherein the ions comprise sulfate SO₄ ²⁻ ions fromseawater incorporated into the frac fluid.
 14. The method of claim 1,wherein forming the mineral comprises precipitating the mineral.
 15. Themethod of claim 1, comprising adjusting composition of the frac fluid inreal time to form the mineral as a mineral matrix having a packingdensity that varies from near wellbore to far field.
 16. The method ofclaim 1, wherein the frac fluid degrades and removes kerogen from rockin the geological formation, wherein removal of the kerogen createsvoids in the rock, and wherein forming the mineral in the fracturescomprises forming the mineral in one of the voids or on a surface of therock outside of the voids, or a combination thereof.
 17. A method offorming proppant in situ in a geological formation, comprising: pumpinga fracturing fluid through a wellbore into the geological formation;hydraulically fracturing the geological formation with the fracturingfluid to generate fractures in the geological formation; and forming theproppant in situ in the fractures by forming mineral in the fracturesvia hydrothermal synthesis of the mineral from ions in the fracturingfluid and precipitating the mineral from the fracturing fluid onto rockin the fractures, wherein the proppant is the mineral.
 18. The method ofclaim 17, wherein the ions comprises iron ions and sulfate ions.
 19. Themethod of claim 17, wherein the ions comprises iron Fe³⁺ ions.
 20. Themethod of claim 17, wherein the ions comprise sulfate SO₄ ²⁻ ions. 21.The method of claim 17, wherein the precipitating the mineral onto therock comprises depositing the mineral as crystallites on faces of thefractures.
 22. The method of claim 17, comprising adjusting compositionof the fracturing fluid in real time to form the mineral as a mineralmatrix comprising a packing density that varies from near wellbore tofar field.
 23. The method of claim 17, wherein forming the mineralcomprises oxidizing the rock with the fracturing fluid, wherein thefracturing fluid comprises an oxidizer.
 24. The method of claim 23,wherein the fracturing fluid degrades and removes kerogen from the rock,wherein removal of the kerogen creates voids in the rock, and whereinforming the mineral in the fractures comprises forming the mineral inone of the voids or on a surface of the rock outside of the voids, or acombination thereof.
 25. The method of claim 23, wherein the rockcomprises pyrite, and wherein the mineral comprises a jarosite groupmineral.
 26. The method of claim 25, wherein the pyrite comprises aniron sulfide mineral FeS₂, and wherein oxidizing the pyrite comprisesconverting Fe²⁺ in the pyrite to Fe³⁺ and converting sulfide S₂ ²⁻ inthe pyrite to SO₄ ²⁻.
 27. The method of claim 18, wherein the mineralcomprises jarosite, hematite, lepidocrocite, or ferrihydrite, or anycombinations thereof.
 28. The method of claim 18, wherein the mineralcomprises a jarosite.
 29. The method of claim 28, wherein the jarositecomprises jarosite, natrojarosite, hydroniumjarosite, orammoniojarosite, or any combinations thereof.
 30. A method of formingproppant in situ in fractures in a geological formation, comprising:injecting a fracturing fluid through a wellbore into the geologicalformation; hydraulically fracturing the geological formation with thefracturing fluid to generate the fractures in the geological formation;synthesizing mineral from ions in the fracturing fluid via temperatureof the geological formation; and precipitating the mineral to depositthe mineral as a crystallite on faces of the fractures, wherein theproppant comprises the mineral.
 31. The method of claim 30, wherein thesynthesizing comprises hydrothermal synthesis, and wherein theprecipitating and the synthesizing occur contemporaneously.
 32. Themethod of claim 30, comprising adjusting composition of the fracturingfluid in real time to form the mineral in the fractures as a mineralmatrix comprising a permeability that varies from near wellbore to farfield.
 33. The method of claim 30, wherein the fracturing fluidcomprises an oxidizer, wherein the fracturing fluid degrades and removeskerogen from rock in the geological formation, wherein removal of thekerogen creates voids in the rock, and wherein forming the mineral inthe fractures comprises forming the mineral in a void of the voids or ona surface of the rock outside of the voids, or a combination thereof.34. A hydraulic fracturing system comprising: a vessel holding afracturing fluid; a control component to modulate an addition rate of anadditive to the fracturing fluid; a pump to provide the fracturing fluidfrom the vessel through a wellbore into a geological formation tohydraulically fracture the geological formation to generate fractures inthe geological formation; and a control system to adjust a set point ofthe control component to change a concentration of the additive in thefracturing fluid to alter a property of a mineral formed in thefractures via the fracturing fluid.
 35. The system of claim 34, whereinthe mineral comprises a mineral matrix, and wherein the propertycomprises packing density of the mineral matrix.
 36. The system of claim34, wherein the control component comprises a control valve or ametering pump, and wherein the additive comprises an oxidizer or ironions, or a combination thereof.
 37. The system of claim 34, wherein theadditive comprises an oxidizer, and wherein the control component tomodulate the addition rate of the oxidizer to degrade and remove kerogenfrom rock in the geological formation via the fracturing fluid and formthe mineral in voids in the rock or on a surface of the rock outside ofthe voids, or a combination thereof.